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Abstract:

A method and system for metering liquid production at a well comprises an
actuated back pressure control valve, a liquid pump, a liquid flow meter
and a pressure sensor, both intermediate the liquid pump and the back
pressure control valve, and a separator having a liquid discharge
conduit, a pressure sensor and a liquid/gas interface sensor disposed to
monitor a section of the separator. The liquid pump receives a stream of
liquid removed from the monitored section of the separator and moves the
liquid stream through the flow meter and the back pressure control valve.
A controller receives signals from the pressure sensors and the interface
sensor, and operates the liquid pump at a speed to maintain an interface
in the monitored section within a predetermined range while positioning
the back pressure control valve to maintain the pressure at the flow
meter above a pressure at which bubbles may form.

Claims:

1. A method of controlling an interface in a separator section while
metering liquid removed from the separator section comprising: providing
a first pressure sensor in a separator to generate a signal to a
controller; providing a liquid pump having an inlet coupled to receive a
liquid flow stream through a liquid discharge connection on the
separator; providing a back pressure control valve positionable to choke
the liquid flow stream discharged from an outlet on the liquid pump;
providing a liquid flow meter intermediate the outlet of the liquid pump
and the back pressure control valve; providing an actuator to receive a
signal from the controller and to position the back pressure control
valve to maintain a minimum pressure on the liquid flow stream adjacent
to the liquid meter at a pressure equal to or greater than a
predetermined amount above a separator pressure detected by the first
pressure sensor; providing a second pressure sensor to detect the
pressure of the liquid flow stream intermediate the outlet on the liquid
pump and the back pressure control valve; coupling an
electrically-powered motor to operate the liquid pump; disposing a
liquid/gas interface sensor proximal a liquid section of the separator;
generating a signal to the controller using the liquid/gas interface
sensor corresponding to an elevated position of a liquid/gas interface in
a monitored section of the separator adjacent the liquid discharge
connection; generating a signal using the controller to condition an
electrical current flow to the motor to accelerate a rate at which the
liquid flow stream is removed from the monitored section of the separator
through the pump; generating a signal using the controller to
re-condition the electrical current flow to the motor to reduce the rate
at which the liquid flow stream is removed from the monitored section of
the separator through the pump; using the liquid meter to measure the
rate at which the liquid flow stream is removed from the monitored
section of the separator and to generate a plurality of signals to the
controller corresponding to a plurality of measurements; and using the
plurality of measurements made within a given time period to determine
the amount of liquid removed from the separator through the liquid pump
and the back pressure control valve.

2. The method of claim 1 wherein the electric motor is powered by an
alternating current; and generating a signal using the controller to
condition an electrical current flow to the motor to accelerate a rate at
which the liquid flow stream is removed from the monitored section of the
separator through the pump comprises: generating a signal using the
controller to a variable frequency drive unit receiving current from a
power distribution lateral; wherein the current is conditioned by
manipulation of the frequency.

3. The method of claim 1 wherein the liquid removed from the monitored
section of the separator comprises oil.

6. The method of claim 1 further comprising: providing an automated
liquid sampler intermediate the outlet of the liquid pump and the back
pressure control valve to obtain and store a plurality of samples of the
liquid flow stream.

7. The method of claim 6 further comprising: using the controller to
generate a signal to activate the automated liquid sampler to obtain a
sample; wherein the controller generates a signal to activate the
automated liquid sampler to obtain a sample based using a frequency
dependent upon the rate at which the liquid is removed from the monitored
section of the separator.

8. The method of claim 1 further comprising: providing a supply of a
chemical; providing a chemical pump operated by an electric motor, the
chemical pump configured to inject chemical into the liquid flow stream
removed from the separator; generating a signal to the electric motor to
operate the chemical pump at a speed that corresponds to a targeted
chemical injection rate proportional to the rate at which liquid is
removed from the separator.

9. The method of claim 8 wherein the chemical is one of a scale
inhibitor, an oxygen scavenger, a corrosion inhibitor, a paraffin
inhibitor and friction reducer.

10. A method of controlling the position of a liquid/gas interface a
separator comprising: disposing a liquid/gas interface sensor proximal a
section of the separator to monitor a position of a liquid/gas interface
therein; detecting with the liquid/gas interface sensor an elevated
position of the liquid/gas interface; generating with the liquid/gas
interface sensor a signal corresponding to the elevated position of the
liquid/gas interface to a controller; generating with the controller a
signal to a current conditioning device coupled to a current source;
using the current conditioning device to condition a current from the
current source to an electric motor coupled to operate a pump, having an
inlet to receive a liquid flow stream from the monitored section of the
separator and an outlet to discharge the liquid stream from the pump, at
an accelerated speed to increase the rate of removal of liquid from the
monitored section of the separator in response to the detected elevated
position of the liquid/gas interface; providing a liquid stream flow
meter to measure the flow rate of the liquid flow stream from the outlet
of the pump; storing with the controller data corresponding to flow rates
of the liquid flow stream measured using the liquid stream flow meter;
providing a back pressure control valve intermediate the liquid meter and
a liquid gathering pipe, the back pressure control valve having an
actuator thereon to position the back pressure control valve in response
to a signal from the controller; providing a first pressure sensor to
detect a pressure in the separator and a second pressure sensor to detect
the pressure in the liquid gathering pipe intermediate the pump and the
back pressure control valve; generating with the first pressure sensor a
signal to the controller corresponding to the detected pressure in the
separator; generating with the second pressure sensor a signal to the
controller corresponding to the detected pressure in the liquid gathering
pipe intermediate the pump and the back pressure control valve; and
generating a signal with the controller to the actuator to position the
back pressure control valve to maintain the pressure of the liquid flow
stream at the liquid meter at a pressure greater than the detected
separator pressure.

17. The method of claim 1 further comprising: detecting with the
liquid/gas interface sensor a corrected position of the liquid/gas
interface; generating with the liquid/gas interface sensor a signal
corresponding to the corrected position of the liquid/gas interface to
the controller; generating with the controller a signal to the current
conditioning device coupled to the current source; using the current
conditioning device to condition a current from the current source to the
electric motor coupled to operate a pump at a reduced speed, relative to
the accelerated speed, to decrease the rate of removal of liquid from the
monitored section of the separator in response to the detected corrected
position of the liquid/gas interface.

18. A method of measuring liquid hydrocarbons produced by a well
comprising: providing a well coupled to a first end of a flow line;
providing a separator having an inlet coupled to a second end of the flow
line, a liquid discharge connection and an interface sensor to generate a
signal to a controller corresponding to the position of a liquid/gas
interface in the separator; providing a pump coupled to a variable speed
motor that receives a signal from the controller; coupling the liquid
discharge connection to an inlet of the pump; coupling an outlet of the
pump to a liquid gathering pipe; providing a pressure sensor to generate
a signal to the controller corresponding to a pressure in the liquid
gathering pipe intermediate the pump and the liquid gathering pipe;
providing a back pressure control valve, intermediate the pump and the
liquid gathering pipe, that receives a signal from the controller;
providing a liquid flow meter intermediate the outlet of the pump and the
back pressure control valve to measure the amount of liquid flowing from
the separator; receiving at the controller a signal corresponding to an
elevated position of a liquid/gas interface; generating a signal from the
controller to the pump motor to increase the speed of the motor and the
pump coupled thereto to increase the rate at which liquid flows from the
separator through the liquid discharge connection and through the pump;
receiving at the controller a signal corresponding to a corrected
position of the liquid/gas interface; and adjusting the back pressure
control valve towards a closed position in response to sensing a pressure
in the liquid gathering pipe that is less than a set point pressure that
is equal to a predetermined pressure interval plus the vapor pressure of
the liquid to maintain the pressure of the liquid in the liquid meter
above the vapor pressure of the liquid; wherein the adjusting of the back
pressure control valve in the manner stated maintains the liquid in the
portion of the liquid discharge pipe at a pressure sufficient to suppress
the formation of bubbles to facilitate accurate measurement of the liquid
removed from the separator.

19. The method of claim 18 wherein the liquid meter comprises at least
one of: a turbine meter to measure volumetric flow; a positive
displacement meter to measure volumetric flow; and a Coriolis meter to
measure mass flow.

20. The method of claim 18 further comprising: providing a liquid sampler
intermediate the outlet of the pump and the back pressure control valve
to periodically obtain and store discrete samples of the liquid stream
flowing through the liquid meter; wherein the adjustment of the back
pressure control valve towards a closed position in response to sensing a
pressure in the liquid gathering pipe that is less than the vapor
pressure of the liquid maintains the pressure of the liquid in the liquid
sampler above the vapor pressure of the liquid.

21. The method of claim 18 wherein the liquid meter, the pump and the
pump motor are supported on a skid.

22. The method of claim 21 wherein the separator is supported on the
skid.

23. The method of claim 21 further comprising: disposing a portion of the
liquid gathering pipe adjacent to a skid support; and positioning the
skid on the skid support.

24. The method of claim 22 further comprising: disposing a portion of the
liquid gathering pipe adjacent to a skid support; disposing the second
end of the flow line adjacent to the skid support; positioning the skid
on the skid support.

25. The method of claim 19 further comprising: providing a densitometer
intermediate the outlet of the pump and the back pressure control valve;
and wherein the a liquid meter is a turbine meter.

26. The method of claim 19 further comprising: providing a densitometer
intermediate the outlet of the pump and the back pressure control valve;
and wherein the liquid meter is a positive displacement meter to measure
volumetric flow.

27. The method of claim 19 further comprising: providing a liquid sampler
intermediate the outlet of the pump and the back pressure control valve
to periodically obtain and store discrete samples of the liquid stream
flowing through the liquid meter; and wherein the liquid meter is a
Coriolis mass flow meter.

28. The method of claim 18 further comprising: wherein the controller is
a distributed controller comprising two or more separated controllers
networked to perform a coordinated function.

29. The method of claim 18 further comprising: providing a first
connection and a second connection on piping intermediate the outlet of
the pump and the liquid gathering pipe to facilitate the coupling of a
meter to prove the accuracy of measurements obtained using the liquid
meter.

30. The method of claim 18 further comprising: providing a second pump,
fluidically disposed in parallel with the first pump, and coupled to a
second pump motor; and operating the second pump to facilitate the
removal of liquid from the separator at rates above the capacity of the
first pump.

31. A method for controlling the liquid/gas interface in a separator
comprising the steps of: supporting a first separator with a first skid,
the separator having at least an inlet flange, a gas discharge flange, a
liquid discharge flange, and a liquid/gas interface sensor, and the skid
further supporting an liquid pressure boost pump, a pump motor, an
automated liquid sampler and a flow meter; providing a docking station
comprising a well flow line pipe, a gas gathering pipe, an oil gathering
pipe, each having a flange to facilitate connection to the inlet flange,
the gas discharge flange and the oil discharge flange on the
skid-supported separator; coupling the flow meter to the liquid discharge
flange of the separator to receive and measure the mass flow rate of the
liquid discharged from the separator through the liquid discharge flange;
coupling the automated liquid sampler to the liquid discharge flange of
the separator to facilitate the periodic removal and storage of samples
of the liquid discharged from the separator through the liquid discharge
flange; coupling the liquid pressure boost pump between the liquid
discharge flange of the separator and the flow meter and also between the
liquid discharge flange of the separator and the automated liquid sampler
to boost the pressure of the liquid discharged from the separator prior
to measurement of the flow rate and prior to the taking of samples of the
liquid; positioning the skid on a skid support adjacent to the docking
station; connecting the separator inlet flange to the well flow line
pipe; connecting the separator gas discharge flange to the gas gathering
pipe; connecting the separator liquid discharge flange to the liquid
gathering pipe; receiving full well stream flow from a well through the
well flow line pipe and the inlet flange; detecting an excessively
elevated liquid/gas interface using the liquid/gas interface sensor;
using the liquid/gas interface sensor to generate a signal to a
controller; using the controller to generate a signal to a variable
frequency drive; using a pump motor to operate the liquid pump at an
increased speed based on the conditioned current sent by the variable
frequency drive; and increasing the rate of removal of liquid from the
separator through the liquid pump.

32. The method of claim 31 further comprising the steps: measuring the
flow rate of liquid discharged from the separator liquid discharge flange
and moving through the flow meter; recording the measurements made by the
flow meter over a period of time; obtaining a plurality of liquid samples
over the period of time using the automated liquid sampler; determining
the average chemical composition of the liquid samples obtained using the
automated liquid sampler; and using the mass flow rate data and data
obtained from analysis of the liquid samples to determine the amount of
and composition of the liquid produced by the well during the period of
time.

33. The method of claim 31 wherein the pump motor is powered by a
variable frequency drive.

34. The method of claim 31 wherein the pump motor is an electrically
powered motor.

35. The method of claim 31 wherein the liquid pressure boost pump is a
centrifugal pump.

36. The method of claim 31 wherein the liquid gathering pipe is connected
to deliver the liquid discharged from the separator on the skid, measured
by the flow meter on the skid and periodically sampled by the automated
liquid sampler on the skid to a central conditioning facility.

37. The method of claim 36 wherein the central oil conditioning facility
comprises: a plurality of pipes, each providing a liquid stream from a
well; and a liquid stabilizer to remove lighter hydrocarbon components
from an aggregated stream of liquid that includes the plurality of the
liquid streams.

38. The method of claim 31 wherein the gas gathering pipe that receives
the gas discharged through from the separator gas discharge flange is
connected to deliver the gas to a central gas processing facility.

39. The method of claim 8 wherein the central gas processing facility
comprises a plurality of pipes, each providing a gas stream from a well;
and a gas scrubber to remove heavier hydrocarbon components from an
aggregated stream of gas that includes the plurality of the gas streams.

40. A system comprising: a first skid supporting a first separator, a
liquid pump, a pump motor coupled to the liquid pump, an automated liquid
sampler, and a flow meter, the separator having a liquid/gas interface
sensor, an inlet flange, a gas discharge flange and a liquid discharge
flange thereon; a second skid supporting a second separator that is
smaller in capacity than the first separator, a liquid pump, a pump motor
coupled to the liquid pump, an automated liquid sampler, and a flow
meter, the second separator having a liquid/gas interface sensor, an
inlet flange, a gas discharge flange and a liquid discharge flange
thereon; a docking station having a second end of a flow line connected
at a first end to a producing well and having a flange at the second end
to facilitate the connection of the well to the inlet flange of one of
the first and second separators, a gas gathering pipe with a flange to
facilitate connection to one of the gas discharge flanges of the first
and second separators, a liquid gathering pipe with a flange to
facilitate connection to the liquid discharge flanges of the first and
second separators, and a skid support adjacent the docking station to
receive and support one of the first skid and the second skid; a back
pressure control valve fluidically coupled to dispose the flow meter and
the automated liquid sampler intermediate the back pressure control valve
and the liquid pump on one of the first and second skids; one or more
controllers to receive a signal from the liquid/gas interface sensor of
one of the first and second separators, to receive a signal from a
pressure sensor disposed to detect a pressure in one of the separators on
the first skid and the second skid, to receive a signal from a pressure
sensor disposed to detect a pressure intermediate the liquid pump of one
of the first and second skids and the back pressure control valve, to
generate a speed control signal to one of the pump motors of the first
and second skids, and to generate a positioning signal to the back
pressure control valve; wherein the flange on the second end of the flow
line, the flange on the gas gathering pipe and the flange on the liquid
gathering pipe are positioned at the docking station to be coupled to the
inlet flange, the gas discharge flange and the liquid discharge flange on
the first separator, respectively, when the first skid is supported on
the skid support, and to engage the inlet flange, the gas discharge
flange and the liquid discharge flange on the second separator,
respectively, when the second skid is supported on the skid support;
wherein the controller maintains the liquid/gas interface position of one
of the separators on the first and second skids within a predetermined
range by increasing the speed of the pump motor on one of the first and
second skids in response to the detection of an elevated liquid/gas
interface position in one of the first and second separators, and by
subsequently decreasing the speed of the pump motor in response to
detection of an corrected liquid/gas interface position in the one of the
first and second separators; and wherein the controller maintains the
pressure intermediate the pump of one of the first and second skids and
the back pressure control valve at a predetermined amount above the
detected pressure in one of the separators on the first skid and the
second skid.

41. The system of claim 40 wherein the controller maintains the
liquid/gas interface position of one of the separators on the first and
second skids within a predetermined range by generating a signal to a
variable frequency drive coupled to a current source to condition a
current to the pump motor on one of the first and second skids.

42. The system of claim 40 wherein the liquid pump is a centrifugal pump.

43. The system of claim 41 wherein the first separator on the first skid
has a larger capacity than the second separator on the second skid.

44. The system of claim 40 wherein a gas discharge pipe is provided
intermediate the gas discharge flange on one of the first and second
separators and the gas gathering pipe flange of the docking station and a
liquid discharge pipe is provided intermediate the liquid discharge
flange on the one of the first and second separators and the liquid
gathering pipe flange of the docking station when the one of the first
and second separators is supported on the skid support.

45. A system comprising: a container of chemical agent; a chemical
injection pump to receive the chemical agent from the container and to
inject the chemical agent into a flow stream of liquid produced to the
surface from a geologic formation; an electrically-powered positive
displacement chemical injection pump motor to operate the chemical
injection pump at a variable speed; a flow meter to detect the rate of
flow of the liquid stream; a controller to receive a signal from the flow
meter corresponding to the detected rate of flow of the liquid stream;
and a current conditioning device to receive a current from a current
source, to receive a signal from the controller corresponding to a
current needed to obtain a targeted chemical agent concentration in the
liquid flow stream, and to provide a conditioned current to the chemical
injection pump motor to operate the chemical injection pump at a rate to
provide the targeted chemical agent concentration.

46. The system of claim 45 wherein the current source is an alternating
current electrical distribution grid.

47. The system of claim 45 wherein the chemical agent is one of an
emulsion breaker, a scale inhibitor, a corrosion inhibitor, a paraffin
inhibitor, and a friction reducer.

48. The system of claim 45 wherein the current conditioning device is a
variable frequency drive.

49. The system of claim 45 wherein the current source is a bank of
batteries.

50. The system of claim 49 wherein the batteries are coupled to one or
more solar panels for being periodically recharged.

51. The system of claim 49 wherein the batteries are coupled to a
generator for being periodically recharged; and wherein the controller
monitors a charge level of the bank of batteries and automatically
activates the generator upon detecting a low charge level.

52. The system of claim 51 wherein the generator is powered by gas
discharged from a separator that provides the liquid flow stream.

Description:

STATEMENT OF RELATED APPLICATION

[0001] This application depends from and claims priority to U.S.
Provisional Application No. 61/485,479 filed on May 12, 2011.

BACKGROUND

[0002] 1. Field of the Invention

[0003] This invention relates to a system and a method to measure liquid,
such as oil, produced from an earthen well drilled into the Earth's
crust.

[0004] 2. Background of the Invention

[0005] Earthen wells are drilled into the Earth's crust to access mineral
deposits such as oil and gas. Technological advances in drilling
technology have enabled sections of a well to be drilled horizontally, or
at a highly-deviated angle from vertical, and within a targeted geologic
formation to dramatically increase the surface area through which fluids
residing in the geologic formation (hydrocarbons) may feed into the
completed section of the well. Where wells are drilled in geologic
formations having favorable properties such as, for example, shale, the
formation may be hydraulically fractured to dramatically decrease
resistance to the flow of fluids residing in the formation into the well
to increase production rates.

[0006] For a well producing liquid comprising lighter hydrocarbon
components such as, for example, propane and ethane, the operating
pressure in a separator to which the well is produced determines the
extent to which these lighter hydrocarbon components are allowed to
evaporate into a gas phase. At high pressure in the separator, the liquid
phase emerging from the separator has a high bubble point pressure
because the high pressure suppresses evaporation of the lighter
hydrocarbon components into the gas phase. At low pressure in the
separator, the liquid phase emerging from the separator has a low bubble
point pressure because the low pressure promotes evaporation of the
lighter hydrocarbon components into the gas phase.

[0007] Conventional field production facilities utilize multiple
separators arranged in sequence to stepwise de-pressure the liquid phase.
A separator is generally sized to provide a predetermined residence time
for a given flow rate of production to be gravity separated therein. A
two-phase separator includes a liquid section near the bottom of the
separator and a vapor section near the top. A three-phase separator
includes a water section, or water boot, at the bottom, a vapor section
near the top and an oil section generally intermediate the water section
and the vapor section. In a three-phase separator, a weir may be disposed
as a barrier to isolate an oil section from a water section and
positioned to facilitate the removal of a top layer of oil floating on
water to the oil section. It will be understood that a conventional
separator may further include mist (coalescence) pads, interface sensors
and control valves to maintain a gas/liquid interface and an oil/water
interface within certain operating ranges.

[0008] In conventional field production facilities with two or more
separators arranged in sequence, a high-pressure separator receives the
full well stream production from a well through a flow line and separates
the full well stream production into a high-pressure gas stream and a
high-pressure liquid stream or, where a three-phase separator is used, a
high-pressure gas stream, a high-pressure oil stream and a water stream.
The liquid stream (or the oil stream) is controllably removed from a
high-pressure separator through a dump-valve that cooperates with a
controller and a liquid/gas interface sensor, such as a float assembly,
to maintain the liquid/gas interface within a predetermined operating
range. The liquid (or oil) is generally piped from the high-pressure
separator to an intermediate-pressure separator operating at a pressure
substantially below the pressure of the high-pressure separator. In the
intermediate-pressure separator, the lighter hydrocarbon components of
the liquid (or oil) evaporate to form an intermediate-pressure gas
stream, substantially richer (energy content per scf) than the gas stream
from the high-pressure separator, and a liquid/gas interface is
established and maintained within the intermediate-pressure separator
using a control valve cooperating with an interface sensor.

[0009] Gas discharged from the intermediate-pressure may be vented or,
more likely, incinerated to minimize the environmental effect. In some
cases, some of the gas discharged from the intermediate-pressure
separator may be compressed to boost the pressure of the gas to a
pressure sufficient to permit the boosted portion of the gas stream from
the intermediate-pressure separator to be combined with the gas stream
discharged from the high-pressure separator. Liquid (or oil) may be
removed from an intermediate-pressure separator through a control valve
that cooperates with a liquid/gas interface sensor in the
intermediate-pressure separator to maintain a liquid/gas interface within
the intermediate-pressure separator in the same manner as with the
high-pressure separator. The liquid (or oil) removed from the
intermediate-pressure separator may be piped to a low-pressure separator
for further processing.

[0010] In the low-pressure separator, the lighter hydrocarbon components
of the liquid (or oil) stream evaporate to form a very rich gas stream
and a liquid/gas interface is established and maintained within the
low-pressure separator using a control valve cooperating with a
liquid/gas interface sensor. The gas stream removed from the low-pressure
separator is vented or, more likely, incinerated to minimize
environmental effects. In some cases, the gas discharged from the
low-pressure separator may be compressed to allow it to be combined with
the gas stream discharged from the intermediate-pressure separator or,
alternately, with the gas stream discharged from the high-pressure
separator. The liquid (or oil) stream is removed from the low-pressure
separator through a control valve cooperating with a liquid/gas interface
sensor in the same manner as with the high-pressure separator and the
intermediate-pressure separator. The liquid (or oil) stream removed from
the low-pressure separator is piped to a stock tank at the well
maintained at or very near atmospheric pressure.

[0011] The liquid (or oil) that accumulates in the stock tank is
periodically unloaded to a mobile tanker for sale and shipment via truck
or train to a refinery. It will be understood that, where the liquid is a
mixture of oil and water, the water can be separated from the oil in
transport or at the destination where the liquid is unloaded from the
mobile tanker. Alternately, the stock tank can be drained from the bottom
to eliminate the water from the liquid mixture prior to loading the oil
onto the mobile tanker. The stock tank may be equipped with a floating or
a fixed roof to facilitate the application of blanket gas at a pressure
of generally between 0.05 and 0.5 pounds per square inch to prevent air
from entering the tank during unloading. The gas in the stock tank when
pressured in excess of the blanket gas pressure will be vented or, in
some cases, incinerated to minimize environmental effect. In some cases,
the stock tank may be equipped with a vapor recovery unit (VRU) to
recover and compress at least some of the rich, hydrocarbon gas that
evaporates from the oil stored in the stock tank to a pressure high
enough so that the compressed gas can be combined with the gas stream
from the low-pressure separator. A VRU for a stock tank is expensive to
purchase, install and to operate because of the large compression ratio
required to compress nearly-atmospheric gas off the stock tank to the
pressure of the gas stream from the low-pressure separator. Generally,
the cost of operating a VRU will exceed any economic benefit of capturing
the hydrocarbons that evaporate in the stock tank. As a result, many
operators forego the capture of stock tank vapors and instead incinerate
stock tank vapors, thereby resulting in unwanted environmental emissions.

[0012] The revenue obtainable from the purchaser such as, for examples, a
refinery, pipeline operator, or trader, for a given volume of oil is
generally lower where light hydrocarbon components (such as ethane and
propane) remaining in the oil raise the vapor pressure of the oil above a
specified threshold. Typically, a purchaser will reduce the price paid to
a producer for a given volume of oil where the vapor pressure exceeds an
optimal vapor pressure threshold or range. For this reason, it is
advantageous for the producer to stabilize the oil prior to sale or
transfer by extracting lighter hydrocarbons from the oil prior to
delivery. Preferably, the oil can be stabilized in a manner that captures
the lighter hydrocarbon components for delivery to a market without
excessive processing costs and without undue investment in production
facilities (for example, multiple separators and related scrubbers,
compressors, valves, stock tanks and an incinerator) for each individual
lease or each individual well.

[0013] An advantage obtained by the use of conventional production
facilities, including a stock tank, is that a stock tank facilitates the
measurement of produced oil stored in the stock tank so that the owner of
the mineral lease from which the oil is produced can be credited with the
correct amount of royalties. With a cylindrical stock tank, for example,
the volume of oil in the stock tank can be determined both before and
after a volume of oil is pumped from the stock tank into a mobile tanker
for transport to a purchaser. As a result, a stock tank at the well
surface location provides a method of accurately determining royalties to
be paid to the owner of the lease from which a well produces.

[0014] Disadvantages of the use of conventional production facilities and
a stock tank include economic loss and environmental pollution. For
example, the use of a high-pressure separator, an intermediate-pressure
separator and then a low-pressure separator to stepwise de-pressure
produced liquid (or oil), and the use of an intermediate-pressure gas
compressor, a low-pressure gas compressor, and perhaps a VRU to
consolidate multiple gas streams into a single high-pressure gas stream,
require large investments in compressors, scrubbers, piping, sensors,
control instruments and valves, and these components then require
numerous gaskets, flanges and packing glands in order to minimize the
unwanted release of environmentally-harmful hydrocarbons such as volatile
organic compounds (VOCs). In addition, motors needed to drive compressors
require large amounts of energy and, depending on the energy source, may
result in the release of additional unwanted combustion products into the
environment. When a compressor or a VRU fails, the lighter hydrocarbon
components that inevitably evaporate from produced oil must be
incinerated to sustain production, thereby resulting in further unwanted
emissions. These sources of VOC emissions, combustion products and
incinerator emissions must be tracked and monitored, and additional
pieces of equipment such as compressors, stock tanks and related support
equipment must be maintained and periodically tested, and the results of
the tests must be recorded and submitted in support of environmental
compliance reports to federal and state environmental agencies.

[0015] Another costly consequence of using conventional production
facilities for producing a well relates to excessive volatility
deductions for oil delivered to a purchaser from a stock tank. The use of
conventional production facilities causes lighter hydrocarbon components,
such as ethane and propane, to be retained in the oil in concentrations
sufficient to elevate the vapor pressure of the oil beyond the optimal
level for refining. Merely de-pressuring oil by, for example, storing it
in a stock tank, does not mean that 100% of the lightest hydrocarbon
components are removed from the de-pressured oil. The retention of even
small concentrations of light hydrocarbon components in the oil
dramatically raises the vapor pressure of the oil beyond the optimal
level for refining. In addition to unwanted deductions in the price
obtainable for oil sold to a purchaser, some pipeline operators impose
strict limits on the vapor pressure of oil to be shipped through
pipelines to prevent entrained light hydrocarbon components from
evaporating and creating a gas phase that impairs pipeline capacity and
operations.

[0016] There is a need, therefore, for a method and a system to produce a
well in a manner that reduces unwanted environmental emissions, to
facilitate the accurate determination of royalties to be paid to the
mineral lease owner(s), and to reduce the environmental compliance burden
on the operator of the production facilities used to produce the well.
There is a need, therefore, for a method and a system to produce a well
in a manner that reduces the considerable up-front investment required to
purchase, fabricate, install and operate conventional production
facilities.

[0017] There is a further need for a method and system of aggregating oil
streams from multiple wells to enable economical conditioning of the
aggregated oil stream to conform the vapor pressure and to thereby avoid
deductions in the price obtainable from a purchaser upon delivery of the
oil. It should be understood that such a method and system requires that
the oil be accurately metered prior to being aggregated and conditioned
to ensure accurate determination of royalties due to lease owners.

SUMMARY

[0018] The present invention provides a method and a system for producing
oil that satisfies some or all of the aforementioned needs. The present
invention provides a method of and a system for maintaining the position
of a liquid/gas interface within a separator within a given range. The
present invention provides a method of accurately metering oil at a well
as it is removed from a separator and without de-pressuring the oil for
storage in a stock tank. The present invention comprises a method of
economically reducing environmental emissions associated with oil
production while providing for the accurate determination of royalties
due the lease owner. The present invention provides a method of
simultaneously reducing capital investment in field production facilities
needed for producing multiple wells while eliminating sources of unwanted
environmental emissions. The present invention provides a method of and a
system for obtaining greater utility from production facilities operated
at the lease, lower investment in production facilities and a greater
return on investment in production facilities used to produce the lease.
These advantages are obtained by providing a production facility system
that enables an operator to economically and reliably turndown (i.e.,
reduce capacity of) the production facility as the production capacity of
the well declines. By providing only as much production facility capacity
as is actually needed, the overall investment in a plurality of wells can
be minimized and the return on investment in production facilities can be
increased. This aspect of the invention is especially beneficial where
oil-producing wells exhibit a steeply-declining production capacity with
an inordinately large portion of the total recoverable hydrocarbons
produced within months or even weeks of the onset of production. This
type of production capacity decline is characteristic of wells that
produce from fractured shale formations.

BRIEF DESCRIPTION OF THE DRAWINGS

[0019] FIG. 1 is a side elevation view of a first separator and a second
separator sequentially coupled one after the other as they are used in a
conventional production facility sized to produce the maximum rate
obtainable in the production cycle of a lease.

[0020]FIG. 2 is an end elevation view of the first separator and first
skid.

[0021]FIG. 3 is a side elevation view of one embodiment of a first
skid-mounted separator and related equipment that may be used to
implement the method and system of the present invention.

[0022]FIG. 4 is an elevation view of one embodiment of a docketing
station that can be used to couple to the first skid-mounted separator
and related equipment of FIG. 3 that may be used to implement the method
and system of the present invention.

[0023]FIG. 5A is a perspective view elevation view of one embodiment of
an oil pressure boost pump and related pump motor supported on the
embodiment of the first skid of FIG. 3, the oil pressure boost pump
comprising a gear pump.

[0024]FIG. 5B is a perspective view elevation view of one embodiment of
an oil pressure boost pump and pump motor supported on the embodiment of
the first skid of FIG. 3, the oil pressure boost pump comprising a
centrifugal pump.

[0025]FIG. 6 is a schematic illustrating the input and/or output
connections of a central programmable logic controller (controller)
electronically coupled to the pump motor, the oil sampler, an interface
sensor and an emergency shut-down (ESD) system.

[0026]FIG. 7 is a side elevation view of an embodiment of an oil
stabilizer that may be used at a central oil conditioning facility fed by
the oil stream from the first skid-mounted separator of FIG. 3, via the
oil gathering pipe, and by additional oil streams from separators at
other leases aggregated together to form a large oil stream to apply
economies of scale to the oil stabilization process.

[0027]FIG. 8 is a side elevation view of an embodiment of a second skid
supporting an oil pressure boost pump, a pump motor, a flow meter and an
oil sampler for connecting to a separator supported off the skid.

[0028]FIG. 9 is an elevation view of one embodiment of a docking station
to couple to the equipment supported on the second skid of FIG. 8 that
may be used to implement an alternate embodiment the method and system of
the present invention.

[0029]FIG. 10 is a side elevation view of an embodiment of a third skid
supporting a second, turndown separator, smaller than the separator on
the skid in FIG. 3, and related equipment with the third skid supported
on an embodiment of a skid support at the docking station of FIG. 4.

[0030]FIG. 11 is a high-level flow chart illustrating an embodiment of a
method for allocating hydrocarbons to a well on a mineral lease produced
using the methods and systems of the present invention.

[0031]FIG. 12 is a high-level flow chart illustrating an embodiment of a
method for determining the hydrocarbon production for a well by metering
the liquid at the well surface location in accordance with the present
invention.

DETAILED DESCRIPTION

[0032] The present invention provides a method of economically and
environmentally optimizing production facilities for producing wells
drilled in oil-bearing geologic formations. In one embodiment, the
present invention provides an improved method of controlling the liquid
(or oil) level in a separator used to process production from a well
while accurately measuring, at a high pressure, liquid (or oil) produced
by the well.

[0033] The disclosure that follows uses the term "liquid" in referring to
a fluidic material produced from a geologic formation and separated from
a gas phase in a separator. The term "liquid," as used herein, may refer
to oil or, in the alternative, the term "liquid" may refer to a mixture
of water and oil that, for example, might be obtained from a two-phase
separator.

[0034] The measurement of liquid production at high pressure prevents the
need for a large number of vessels and related processing equipment to
produce the well, and prevents the need for a much larger investment in
production facilities to produce the well. The measurement of the liquid
production at high pressure also prevents the need to de-pressure the
liquid produced by the well so that it can be stored and measured using a
stock tank.

[0035] In one embodiment, the present invention may be used to reduce the
amount of the investment in production facilities at or near a well
surface location by reducing the size and number of vessels and related
equipment needed to process the production rate expected from the well.
In one embodiment of the method and system of the present invention, a
first, high-capacity production facility can be used early in the
production cycle to produce the maximum production rates expected from
the well and a second, reduced capacity production facility can be
subsequently installed to free up the first, high-capacity production
facility for use at other wells that produce at sufficient rates to
warrant a high-capacity facility. The first, high-capacity production
facility and the second, reduced or "turndown" capacity production
facility can, in one embodiment, be supported on skids to be sequentially
coupled to a docking station at the well surface location. This
arrangement provides for a "plug-out / plug-in" substitutability of the
second "turndown" production facility for the first, high-capacity
production facility, thereby allowing the more costly high-capacity
facility to be used at another well.

[0036] Accordingly, the method and system of the present invention enables
the exploitation of mineral deposits using a more economical and
environmentally safer production facility that facilitates the accurate
determination of royalties due to be paid to the lease owner while
reducing environmental emissions and reduced overall investment.

[0037] One embodiment of the method of producing a well comprises the
steps of: providing a first separator located generally near the surface
location of a well; providing a pump to increase the pressure of a liquid
stream leaving the separator through a liquid discharge pipe to suppress
the formation of gas bubbles in the liquid discharge pipe immediately
downstream of the pump; coupling a flow meter to measure the rate of the
liquid stream in the liquid discharge pipe downstream of the pump;
connecting a flow line to an inlet pipe on the first separator to deliver
full well stream production from the well to the separator; connecting
the liquid discharge pipe to a liquid gathering pipe; connecting the
liquid gathering pipe to a central conditioning facility; connecting a
gas discharge pipe through which gas is discharged from the separator to
a gas gathering pipe; receiving full well stream production fluid from
the well through the flow line and separator inlet pipe and into the
separator; removing a gas stream from the separator through the separator
gas discharge pipe and the gas gathering pipe; removing a liquid
discharge stream from the separator through the liquid discharge pipe and
the pump to the liquid gathering pipe; using the pump to increase the
pressure of the liquid discharge stream at the liquid flow meter; using
the flow meter to measure the liquid removed from the separator;
recording the flow rate of the liquid removed from the separator through
the pump; moving the liquid from the liquid gathering pipe to the central
conditioning facility; combining the liquid stream with one or more
additional liquid streams from one or more additional wells delivered to
the central conditioning facility to form an aggregated liquid stream;
using a stabilizer at the central conditioning facility to remove lighter
hydrocarbon components and to thereby adjust the composition of the
aggregated liquid stream so that the vapor pressure of the conditioned
stream is favorable for selling the conditioned stream to a purchaser;
delivering the conditioned stream from the central conditioning facility
to the purchaser; using data obtained and stored by the meter to
determine the amount and nature of the hydrocarbons produced from the
well during a time period; and determining a royalty to be paid to the
owner of the lease from which the well produces as a portion of revenues
obtained from the sale of the conditioned oil and associated gas.

[0038] In one embodiment of the invention, the method further comprises
the step of providing an automated liquid sampler downstream of the pump
to periodically extract and store a sample of liquid from the liquid
stream discharged from the separator and pumped through the pump. In one
embodiment, the separator, the pump, a pump motor, the automated liquid
sampler and related equipment are supported on a skid. In an alternate
embodiment, the pump, a pump motor, the automated liquid sampler and
related equipment are supported on a skid positioned proximal an existing
separator so that the liquid discharged from the separator can be easily
routed to an inlet of the pump on the skid. In another embodiment of the
method and system of the present invention, a docking station is provided
to position an end of a flow line adjacent a skid support on which a skid
supporting the separator is supported. In another embodiment of the
present invention, a docking station is provided to position an end of a
liquids gathering line adjacent a skid support on which a skid supporting
a pump and a flow meter are supported. The pump may receive and boost the
pressure of a liquid stream from a separator to facilitate metering at a
pressure above the bubble point pressure of the liquid stream.

[0039] In one embodiment of the method of the present invention, a liquid
level in a section of the separator may be maintained within a
predetermined operating range using a liquid/gas interface sensor, such
as a guided wave radar device, coupled through a controller and a current
conditioning device, such as a variable frequency drive, to a pump motor
that operates the pump. The liquid/gas interface sensor may be mounted in
or near the top of the separator to monitor the liquid/gas interface
position in, for example, a monitored section of the separator in which
oil resides, and to maintain the liquid/gas interface position within a
desired operating range. In one mode of operation, the liquid/gas
interface sensor detects an elevated level in the monitored section of
the separator and generates a corresponding signal to the controller. The
controller processes the signal received from the liquid/gas interface
sensor and generates a corresponding speed signal to the current
conditioning device. The current conditioning device then provides a
conditioned current to a pump motor that is coupled to operate the pump,
for example, to rotate the input shaft of the pump at an increased rate
to increase the rate at which liquid is removed from the monitored
section of the separator. The pump operated by the pump motor has a pump
inlet, such as a flange, disposed in fluidic communication with the
monitored section of the separator and a pump outlet, such as a discharge
flange, in fluidic communication with a flow meter. In response to an
elevated position detected by the liquid/gas interface sensor, the
processor generates a signal to increase the operating speed of the pump
and to increase the rate at which liquid is removed from the monitored
section of the separator through the pump and through the liquid
discharge pipe. An increased liquid removal rate will generally result in
a reduced or corrected position of the liquid/gas interface in the
monitored section of the separator which, upon being detected by the
liquid/gas interface sensor, causes the liquid/gas interface sensor to
generate a corresponding signal to the controller which, in turn,
generates a revised signal to decrease the speed of the pump motor and
the pump, and to thereby slow the rate of removal of liquid from the
monitored section of the separator. The pump operates to maintain the
pressure of the liquid in the flow meter disposed downstream of the pump
above the bubble point pressure of the liquid to suppress the formation
of bubbles in the liquid and to thereby facilitate accurate measurement.

[0040] The corrective action described above is automatically implemented
using the equipment described above, or equivalents thereof, and will
maintain the position of the liquid/gas interface in the monitored
section of the separator within a desired operating range. It will be
understood that the current conditioning device, such as a variable
frequency drive, may be disposed at the well surface location at a safe
distance from the hydrocarbon processing equipment (separator, pump, flow
meter, etc.) for purposes of safety, and that the pump motor will be of
an explosion proof design.

[0041] The liquid/gas interface sensor may, in some embodiments of the
method and system of the present invention, be mounted on the separator
using a bridle and a related piping loop external to the separator if a
top nozzle, man way or other structure to facilitate internal mounting
within the separator vessel is not available or otherwise not convenient.
The liquid/gas interface sensor may generate either an analog or digital
signal to a controller and, in one embodiment of the present invention,
the controller may generate a variable frequency signal to directly
control the speed of the pump motor. Alternately, the controller may
simply provide a signal to a separate controller that generates, for
example, a variable frequency signal to the pump motor to operate the
pump motor and the pump coupled thereto at the desired speed.

[0042] The pump and pump motor may be coupled one to the other using a
shaft fitted with circumferential seals to contain the pressure within
the pump case or, alternately, an output shaft of the pump motor may be
magnetically coupled to an input shaft of the pump using, for example, a
plurality of corresponding magnets or, alternately, rare earth magnets
disposed within a non-magnetic case (such as stainless steel) to provide
for torque transmission from the pump motor to the pump (or pump input
shaft) without the use of fluidic seals to contain the pressure within
the pump case. The above-described steps of monitoring the liquid/gas
interface position in the monitored section of the separator using a
liquid/gas interface sensor, detecting a condition corresponding to an
excessive level in the monitored section of the separator, using the
liquid/gas interface sensor to generate a signal to the controller, using
the controller to generate a signal to the pump motor and then again
using the liquid/gas interface sensor to sense a corrected level in the
monitored section of the separator may, in one embodiment of the present
invention, be repeated as part of a continuous system for monitoring and
controlling the position of the liquid/gas interface within the separator
and for boosting the pressure of the liquid stream removed from the
monitored section of the separator to a pressure above the bubble point
pressure to facilitate accurate metering of the liquid stream at the well
surface location.

[0043] The equipment used to implement this system may be used to perform
other control tasks. For example, the controller used to receive the
signal from the liquid/gas interface sensor and to generate a
corresponding signal to the pump motor may, in some embodiments of the
present invention, also be used to control an emergency shut-down (ESD)
valve disposed at the wellhead. As another example, the controller may
also be used in conjunction with a separator pressure sensor to monitor
and control the pressure in the separator by controlling an actuated back
pressure valve on a gas discharge pipe through which gas separated from
the liquid in the separator is removed from the separator. As another
example, the controller may also be used to receive a signal from a
pressure sensor disposed to sense the pressure within the separator (or
within a pipe carrying fluid discharged from the separator, such as the
gas discharge pipe or the liquid discharge pipe), to generate a signal
corresponding to the sensed pressure to an actuator on a back pressure
control valve disposed in the liquid discharge pipe and downstream of the
pump and the flow meter, and to use the signal to position the back
pressure control valve to maintain the pressure upstream of the valve and
in the liquid discharge pipe at the flow meter at a pressure equal to the
sensed pressure plus a predetermined incremental amount of additional
pressure to suppress the formation of bubbles. As another example, the
controller may be used in conjunction with a separator pressure sensor
and a liquid gathering pipe pressure sensor to facilitate control of the
pressure of the liquid stream at the flow meter disposed downstream of
the pump. As stated above, the pump boosts the pressure of the liquid
stream emerging from the separator so that the liquid stream can be
metered by the flow meter at a pressure above the bubble point pressure
of the liquid. If the pressure in the liquid gathering pipe disposed
downstream of the meter is below a desired set point pressure which,
according to the example given above, is at a predetermined pressure
interval above the bubble point pressure of the liquid (which may be
provided by the separator pressure sensor), the controller can be used to
modify the position of the liquid back pressure control valve towards
closure and to thereby increase and then maintain the pressure at the
flow meter above the bubble point pressure. Downstream of the flow meter,
the liquid stream will incur a pressure drop across the back pressure
control valve and, where the pressure in the liquid gathering pipe
downstream of the back pressure control valve is below the bubble point
pressure, a portion of the lighter hydrocarbon components of the liquid
stream will evaporate within the liquid gathering pipe, but such
evaporation will not impair accurate metering of the liquid stream
removed from the separator and boosted by the pump.

[0044] In one embodiment of the system, a liquid measurement sub-system
for determining the mass flow rate and one of the density and the
chemical composition of the liquid phase is provided. For example, the
liquid measurement sub-system may, in one embodiment, comprise a Coriolis
mass flow meter, an automated liquid sampler and a back pressure control
valve disposed on one of the liquid discharge pipe or the liquid
gathering pipe to receive a stream of liquid removed from the monitored
section of the separator. Embodiments of the present invention including
the use of a back pressure control valve on the liquid discharge pipe or
on the liquid gathering pipe provide the back pressure control valve at a
location that is downstream of the pump, downstream of the flow meter and
downstream of the automated liquid sampler to facilitate the measurement
of the liquid flow rate without error or inaccuracy that would be
introduced by the formation of bubbles in the liquid stream. These
embodiments utilizing a Coriolis flow meter facilitate both accurate mass
flow measurement and liquid density measurement in the Coriolois meter,
along with efficient liquid sampling in the automated liquid sampler.
Like a back pressure control valve on the gas discharge pipe, a back
pressure control valve may be disposed downstream of the pump, the liquid
sampler, and the Coriolis mass flow meter, and downstream of the metering
sub-system. Alternately, a back pressure control valve may be disposed
off-skid from the pump, the automated liquid sampler and the pump motor,
and on the liquid gathering pipe. It will be understood that the purpose
of the back pressure control valve on the liquid discharge pipe or the
liquid gathering pipe is to provide a pressure that facilitates the
accurate metering of the liquid stream removed from the monitored section
of the separator by isolating the portion of the liquid stream at and
upstream of the meter from a pressure in the liquid gathering pipe that
may be below the bubble point pressure of the liquid stream. The back
pressure control valve, whether it be provided immediately downstream of
the liquid metering sub-system and on a skid, or off the skid at on the
liquid gathering pipe, may be used to provide sufficient back pressure on
the portion of the liquid stream at the flow meter so that the boost in
pressure provided by the pump facilitates accurate metering by ensuring
that the metered liquid stream is above the bubble point pressure of the
liquid.

[0045] The operation and control of the back pressure control valve may be
understood by consideration of an example of how fluctuations in the
pressure in the liquid gathering pipe might otherwise impair the accurate
metering of the liquid stream emerging from the separator but for the
present invention. Assuming a pressure sensor detects a separator
pressure of, for example, 250 psig, and a second pressure sensor detects
a liquid gathering pipe pressure (downstream of the back pressure control
valve) of 225 psig, it will be understood that at least some of the
lighter components of a liquid stream emerging from the separator would
evaporate upon exposure to the lower pressure of the liquid gathering
pipe, thereby introducing significant metering error at the flow meter.
Even with the pump operating to remove liquid from the monitored section
of the separator, the pressure at the outlet of the pump would be the
same as the pressure in the liquid gathering pipe but for the back
pressure control valve. Stated another way, in the absence of a back
pressure control valve downstream of the pump and flow meter and upstream
of the liquid gathering pipe, the pump would merely remove liquid from
the separator and would not necessarily boost the pressure to facilitate
accurate metering at the flow meter. The back pressure control valve,
then, serves to isolate the outlet of the pump and the flow meter
downstream thereof from the liquid gathering pipe pressure. With a back
pressure control valve disposed downstream of the pump so that the flow
meter is intermediate the pump and the back pressure control valve, and
so that the back pressure control valve and the flow meter are
intermediate the pump and the liquid gathering pipe, the controller will
move the back pressure control valve towards closure in response to a
signal from a second pressure sensor indicating that the pressure in the
liquid gathering pipe between the pump and the back pressure control
valve (as compared to the separator) is below the desired measurement
pressure. Positioning the back pressure control valve towards closure
will enable the pump to impart a pressure boost to the liquid stream
emerging from the separator so that metering of the liquid stream can be
accurately performed at a pressure above the bubble point pressure
(approximately 250 psig, the separator pressure) of the liquid stream.
Downstream of the flow meter, and at the back pressure control valve, the
liquid stream will be de-pressured as it enters the liquid gathering
pipe, but any gas that evaporates as a result of the pressure drop will
not impair accurate metering of the liquid stream.

[0046] In another example, the second pressure sensor disposed on liquid
gathering pipe may detect a pressure of the liquid in the liquid
gathering pipe to be greater than the bubble point pressure of the liquid
stream and greater than the separator pressure as detected by a first
pressure sensor. For example, the separator pressure detected by the
first pressure sensor may be 250 psig and the liquid gathering pipe
pressure detected by the second pressure sensor may be 400 psig. In this
case, the controller will, in response to the signal from the first and
second pressure sensors, generate a signal to the back pressure control
valve actuator to position the back pressure control valve to a fully
open position so that the discharge pressure from the pump will be the
same as the liquid gathering pipe pressure, or 400 psig. It will be
understood that, with this control capacity, the controller can variably
operate the pump at a speed that is necessary to maintain the liquid/gas
interface in the monitored section of the separator within a desired
range while the controller (or another, related controller) maintains the
position of the back pressure control valve as needed to ensure that the
pressure of the liquid stream detected by a second pressure sensor
disposed at or near the flow meter remains above the bubble point
pressure (i.e., the sensed separator pressure).

[0047] It will be understood that the control of the speed of the pump
that maintains the position of the liquid/gas interface in the separator
within the desired range and the control of the back pressure control
valve are not unrelated. For example, an increase in the speed of the
pump motor and in the throughput of the pump, to lower an elevated
position of a liquid/gas interface in the separator, may require the back
pressure control valve to move towards the open position in order to
prevent the pressure of the liquid stream at the flow meter from
increasing to a level above the safe operating pressure of the piping and
equipment. Alternately, a decrease in the speed of the pump motor and the
throughput of the pump, to maintain a corrected position of the
liquid/gas interface in the separator, may require the back pressure
control valve to move slightly towards the closed position in order to
prevent the pressure of the liquid stream at the meter from decreasing to
a pressure below the bubble point pressure of the liquid. For these
reasons, a preferred embodiment of the method of the present invention
provides generally continuous monitoring and adjustment of the speed of
the pump and in the position of the back pressure control valve
downstream thereof.

[0048] In addition to these functions, a controller may be programmed and
connected to other devices and sensors to provide further benefits. For
example, the controller may be programmed to maintain an oil/water
interface in a primary section of a three-phase separator, to position a
back pressure control valve on the gas discharge pipe, to activate,
deactivate and/or adjust the speed of a second pump motor coupled to a
second pump operating in parallel to the first pump, to control the
injection and concentration of injected chemicals to abate corrosion,
scale, paraffin and/or friction, to communicate data indicating the
status and/or alarm conditions of equipment at the well site and to
activate an ESD to shut in the well when conditions warrant. The
controller may also be used to monitor and/or record measurements by the
flow meter, to control the gathering of samples by the automated liquid
sampler and to operate other equipment that may be provided for the
purpose of metering the liquid produced through the separator.

[0049] In one embodiment, a measurement sub-system may comprise a
volumetric flow meter such as, for example, a turbine meter having a
rotary element that spins on an axis disposed generally centrally along
an axis of flow. The rotations of the rotary element in a given period of
time generally correspond to the volume of liquid moving through the
meter. In another embodiment, a measurement sub-system may comprise a
positive displacement flow meter such as, for example, an A. O. Smith
meter. In other embodiments, a turbine meter or a positive displacement
meter may be combined with a densitometer so that, in addition to the
volumetric flow rate of the liquid from the separator, the density of the
liquid can also be obtained with reasonable accuracy, and the density
measurements are combined with the volumetric data from the volumetric
flow meter to enhance the overall accuracy of the determination of the
amount and quality of hydrocarbons produced from the well.

[0050] It should be noted that, where a measurement sub-system comprises a
Coriolis meter, there is no need for a densitometer since a Coriolis
meter provides density measurements of the liquid flowing through the
Coriolis meter. There are several brands of Coriolis meters including
MicroMotion®, a brand of mass flow measurement meter sold by Emerson
Process Management of Boulder, Colo., USA, that uses the principle that
increasing mass flow through a vibrating tube twists the vibrating tube
at an increasing and a measurable displacement corresponding to the mass
flow rate, and the magnitude of the displacement of the tube can be
accurately correlated to enable the accurate determination of the mass
flow rate of the fluid flowing through the tube. Periodic sampling of the
oil using the automated oil sampler enables an operator to determine the
weighted average chemical composition and/or the weighted average density
of the liquid samples captured over a time period. These data taken
together enable an operator to accurately determine the total mass,
volume and chemical composition of liquid flowing through the liquid
discharge pipe within a time period of interest. The Coriolis mass flow
meter uses magnetic sensors to measure the deflection of the tubes in the
meter through which the liquid flows. The sensed deflections are
transmitted to the controller and saved to enable the amount of
production to be determined. The liquid samples taken in the automated
liquid sampler are stored in a storage vessel that is removable from the
liquid sampler to facilitate measurement and analysis in a remote
laboratory environment, for example, by chromatographic analysis, and the
data from the analysis of the aggregated liquid samples may be
transmitted to a central controller, along with the data from the
Coriolis mass flow meter, to facilitate the determination of hydrocarbon
production from the well.

[0051] In one embodiment of the system and method of the present
invention, a measurement sub-system further comprises an automated liquid
sampler. It will be understood that, although a densitometer or a
Coriolis mass flow meter may be used to obtain the density of a liquid,
obtaining an actual sample of the liquid enables the determination of the
chemical composition of the aggregated samples by, for example,
chromatographic analysis. Since the value of a given volume or a given
mass of hydrocarbons may depend, at least in part, on the chemical
composition of the hydrocarbons, two wells producing liquid of identical
density may result in different revenues. The controller may be used, in
addition to the uses described above, to periodically activate an
automated liquid sampler to obtain a sample of the liquid removed from
the separator through the liquid discharge pipe. An automated liquid
sampler can store multiple samples taken over a period of time in a
pressure vessel or a "bomb" that is removable from the automated liquid
sampler. The pressure vessel can be periodically replaced, and the
accumulated liquid sample in the replaced pressure vessel can be analyzed
to obtain a weighted-average chemical composition and/or weighted-average
density of the hydrocarbon component of the liquid sample produced by the
well. In one embodiment of the method and system of the present
invention, a static mixer is disposed upstream of the automated liquid
sampler to ensure that obtained and stored samples of the liquid are
representative of the liquid being removed from the monitored section of
the separator.

[0052] In one embodiment of the method of the present invention, the rate
or frequency at which the automated liquid sampler takes samples can be
tailored to comport with the rate at which liquid flows from the
separator and through the automated sampler sample probe by, for example,
using data provided from a Coriolis mass flow meter or a volumetric flow
meter. In this way, a more representative sample may be accumulated by
the automated liquid sampler by taking samples more frequently when the
flow rate is higher and less frequently when the flow rate is lower.

[0053] Some embodiments of the system and method of the present invention
may be implemented using a separator coupled to a pump. The pump
cooperates through a controller with a liquid/gas interface sensor that
monitors a section of the separator. The controller receives a signal
from an interface sensor disposed to monitor the position of a liquid/gas
interface within a monitored section of the separator and generates a
corresponding signal to the pump motor, which signal may be processed
through other devices such as a current conditioning device, to vary the
speed of the pump motor and to thereby control the flow rate at which
liquid is removed from the monitored section of the separator through the
pump. The pump provides favorable conditions (a pressure above the bubble
point pressure) for metering the liquid in a meter disposed downstream of
the pump but upstream of a back pressure control valve. By eliminating
the need to de-pressure produced liquids to near-atmospheric or
atmospheric pressure, a portion of the produced hydrocarbons can be
retained in the liquid phase instead of being surrendered to the gas
phase by stepwise de-pressuring of the produced liquid. The system and
method of the present invention thereby facilitate the accurate metering
of the hydrocarbons produced while eliminating the need for a stock tank,
an incinerator and intermediate-pressure and low-pressure vessels and
related equipment, such as compressors.

[0054] A metered liquid stream may be carried away from the well location
via the liquid gathering pipe and subsequently commingled with metered
liquid streams from similar production facilities disposed at other
wells. The commingled stream can be efficiently conditioned and treated
at a centralized conditioning facility. For example, using economies of
scale, an operator can capture at a central conditioning facility what
would have otherwise been vented and/or incinerated hydrocarbon gas, and
the operator can thereby stabilize the remaining liquid phase to adjust
the vapor pressure and, at the same time, maximize revenues received upon
sale of the liquids to a purchaser. At the same central conditioning
facility, the commingled liquid stream can be subjected to separation to
remove water and other non-hydrocarbon components. It will be understood
that the throughput or loading of such a centralized conditioning
facility will be less affected by a decline or interruption in production
of any individual well because declining production from a first well is
likely to be replaced or offset by an increase in production from a
second well that contributes to the overall throughput at the central
conditioning facility. This benefit enables an operator to obtain a
substantially greater return from an investment in the centralized
conditioning facility because it can be efficiently and continuously
loaded to achieve a high facility utilization rate as opposed to the less
cost-effective alternative of investing in numerous smaller and less
efficient facilities installed and operated at each individual well.

[0055] As another benefit, the method and system of the present invention
provides for a greatly-reduced facilities footprint at the well
(approximately 5 to 8% of that of a conventional production facility),
the method and system provide for reduced facilities equipment and
installation investment for the production of each well. A single
production facility built in accordance with some embodiments of the
system and method of the present invention can be relocated and re-used
for the production of multiple wells.

[0056] The method and system of the present invention facilitates the
efficient removal and replacement of components to accommodate facilities
turndown as a production capacity of a well declines. For example, many
wells may exhibit a steep decline in production within weeks or months of
the onset of production. Some or all of a separator, liquid pump, a
liquid meter and an automated liquid sampler may be disposed on a first
skid and connected to a well at the onset of production at a high initial
production rate. Once the production rate declines into a range
corresponding to a turndown mode, some or all of this equipment may be
replaced with smaller and less expensive counterparts with a lower
throughput capacity, and the replaced, larger-capacity equipment can be
used at another well to facilitate initial production rates at the well.
Where the equipment is conveniently arranged on a skid, a second,
turndown skid supporting, for example, a smaller separator, a smaller
pump, and a smaller liquid meter, can be brought to the well location,
put in the place previously occupied by the first skid and connected to
the same flow line, gas gathering pipe and liquid gathering pipe that was
connected to the first skid.

[0057] In one embodiment of the method and system of the present
invention, the modular or staged approach to the installation, use,
substitution and removal of production facilities may be best achieved by
positioning equipment and, more specifically, connections to and from the
equipment, in the same locations, relative to the skid support, on the
equipment used for initial production of a well and on the equipment used
to turndown the capacity of the production facilities. For example, if an
embodiment of a first skid were to support a separator, a liquid pump, a
liquid meter, an automated liquid sampler and a back pressure control
valve in certain positions on the first skid so that a flow line from the
well is conveniently connectable to the separator inlet, the liquid
gathering pipe that receives metered liquid is conveniently connectable
to the (downstream end of the) back pressure control valve, and the gas
gathering pipe that receives separated gas is conveniently connectable to
the gas discharge pipe that couples to the gas discharge flange on the
separator, then it will be advantageous to position a smaller capacity
separator, an associated gas discharge pipe and an associated back
pressure control valve in the same relative positions on a second,
turndown skid and with the same-sized connections to facilitate
connection of the equipment on the turndown skid to the flow line, the
gas gathering pipe and the liquid gathering pipe. Similarly, where a
three-phase separator is employed, a water gathering pipe may be
positioned for connection to a water discharge pipe. It will be
understood that this method and system facilitates the convenient and
reliable installation, removal and substitution of production facilities
and lowers the capital investment required to produce a large number of
wells, reduces environmental emissions, maintains the capacity to
accurately allocate production back to the well and provides greater
revenue through strategic and efficient conditioning of aggregated liquid
streams from multiple wells.

[0058] In one embodiment of the method and system of the present
invention, a chemical injection pump, a chemical injection pump motor and
at least one container with a volume of chemical is provided for
introducing, at a controllable rate, one or more chemicals into the
liquid stream removed from the separator. The chemical may be, for
example, an emulsion breaker, a corrosion inhibitor, a scale inhibitor, a
paraffin inhibitor, or a friction reducing agent. The chemical(s) to be
introduced into the liquid stream removed from the monitored section of
the separator depends on the physical characteristics, acidity or
alkalinity, salinity or the compositional chemistry of the produced
liquids and the problems associated therewith. The rate at which the
chemical(s) is introduced into the liquid stream is controllable using
the controller to generate a signal to the chemical pump motor that
operates the chemical injection pump to operate at a rate that ensures a
favorable injection rate and a favorable concentration of the chemical
for the specific rate at which the liquid stream is removed from the
monitored section of the separator. For example, but not by way of
limitation, in response to detection by the liquid/gas interface sensor
that the position of the liquid/gas interface within the monitored
section of the separator is elevated, a signal corresponding to the
elevated position is generated by the liquid/gas interface sensor to a
controller. The controller generates a first signal to increase the speed
of the liquid pump motor to increase the speed of the liquid pump and to
thereby increase the rate at which liquid is removed from the monitored
section of the separator, and the controller generates a second signal to
increase the speed of the chemical injection pump motor to increase the
rate at which chemical is pumped and introduced into the liquid stream
removed from the monitored section of the separator. Later, when the
liquid/gas interface sensor detects a corrected position of the
liquid/gas interface in the monitored section of the separator and the
rate at which liquid is removed from the monitored section of the
separator is downwardly restored, the rate at which the chemical is
injected is also downwardly restored. In this manner, the embodiment of
the method and system of the present invention conserves chemical by
ensuring that an excessive amount of chemical is not injected into the
liquid stream and, at the same time, prevents unwanted emulsions, scale,
corrosion, paraffin formation, flow resistance or other problems to be
abated by the chemical by ensuring that an insufficient rate of chemical
injection is avoided during accelerated periods of removal of liquid from
the monitored section of the separator. Those skilled in the chemical
arts will understand that conventional chemical injection pumps are
generally operated to deliver a sufficient amount of chemical agent for
the maximum anticipated rate of flow of the liquid stream being treated
using the chemical agent, and that, at rates lower than the maximum
anticipated rate, chemical is wasted by maintenance of the chemical
injection rate at the higher, fixed rate. By using the controller to
determine the speed at which the liquid pump motor and the liquid pump
operate, and by using the controller to continuously or intermittently
tailor the chemical injection rate in accordance with the liquid pump
rate, an operator can realize a significant cost savings by preserving
chemical resources.

[0059] Features and elements of embodiments of the method and system of
the present invention may be better understood by reference to the
appended drawings, which are discussed in connection with certain aspects
of the present invention that follow. These appended drawings are not
meant to be limiting of the invention, which is limited only by the
claims that follow.

[0060] FIG. 1 illustrates conventional production facilities used to
produce wells. FIG. 1 is a side elevation view of a first separator 10
and a second separator 30 sequentially coupled one after the other as
these separators are used in a conventional production facility. The
first and second sequential separators 10 and 30 operate at different
pressures, the pressure of high-pressure separator 10 being substantially
higher than the pressure of low-pressure separator 30. The high-pressure
separator 10 comprises an inlet flange 12, a gas discharge flange 14, an
oil discharge flange 16, a water discharge flange 18 on a water boot 15,
and a weir 13 to divide an oil section 17 from a produced liquid section
19. It will be understood that full well stream from a flow line 8 that
is connected to a wellhead (not shown) provides produced fluids into the
separator 10 and against the impingement deflector 9. In the separator
10, water 23 is gravity separated from oil 21 and gas 22. Oil 21 spills
over the weir 13 and into the oil section 17 while the denser water 23
sinks into the water boot 15. Gas 22 moves through the mist eliminator 11
and is discharged through the gas discharge flange 14. Oil 21 is
discharged from the oil section 17 through the oil discharge flange 16
and water 23 leaves the water boot 15 through the water discharge flange
18.

[0061] A liquid/gas interface 25 is established between the oil 21 and the
gas 22, while an oil/water interface level 24 is established between the
oil 21 and water 23. The oil level 29 in the oil section 17 may be
monitored using instruments such as, for example, a float 5 and level
control sensor 4 coupled thereto. Similarly, the oil/water interface 24
may be monitored using a float 3 and level control sensor 4 coupled
thereto. The signals generated by the level control sensors 3 and 4 are
transmitted, either via wire or wirelessly, to actuated valves 28 and 27,
respectively, fluidically coupled to the water discharge flange 18 and
the oil discharge flange 16, respectively, that will open and close to
adjust the associated interface level 24 and oil level 29, respectively,
within the separator 10.

[0062] The oil discharged from the oil discharge flange 16 through the
actuated valve 27 associated with the first separator 10 is routed to the
inlet flange 32 on the second separator 30 where an oil layer 31 will
float above a water layer 33 and a gas phase 35 will remain above the oil
layer 31. The oil stream emerging from the first separator 10 is again
subjected to gravity separation, this time at a lower pressure in the
second separator 30 as compared to the pressure of the first separator
10. It will be understood that, upon depressurization in the second
separator 30, lighter components of the oil will evaporate to form a gas
phase 35 in the second separator 30. In addition, any water that may have
been entrained in the oil spilling over the weir 13 of the first
separator 10 can be gravity separated out of the oil phase in the second
separator 30. Gas is discharged from the second separator 30 through the
gas discharge flange 34 and oil from the oil layer 31 will spill over the
weir 43 into the oil section 37 of the second separator 30 before being
discharged through the oil discharge flange 36. Water from the water
layer 33 in the second separator 30 is discharged through the water
discharge flange 38. In the same manner as described above with respect
to the first separator 10, the liquid/gas interface level 45 and the
water/oil interface level 44 in the second separator are controllable
using floats 3A and 5A, level control sensors 4A and actuated valves 28A
and 27A.

[0063]FIG. 2 is a sectional elevation view of the embodiment of the
second separator 30 of FIG. 1 illustrating the positions of the gas
discharge flange 34, the water discharge flange 38, the water layer 33,
and the oil layer 31 in the separator 30 as is well-known in the art.

[0064] FIGS. 3 through 12 are related to and illustrate embodiments of the
method and system of the present invention. FIG. 3 is a side elevation
view of an embodiment of a skid-mounted separator 50 and related
equipment that may be used to implement one embodiment of the method and
system of the present invention. The skid 51 comprises a first end 51A
and supports the separator 50 above the skid 51 through a pair of pillars
69 spaced one from the other. A skid support 90 may be provided to
support the skid 51. In one embodiment, the skid support 90 is the Earth.
The separator 50 comprises an inlet flange 52 connected to a flow line
flange 92 disposed at the second end of a flow line (the first end, not
shown, being connected to the well), an impingement deflector 59 adjacent
thereto, a gas discharge flange 54 connected to a gas discharge pipe 64,
a liquid discharge flange 56 connected to a liquid discharge pipe 66, a
water boot 57, a water discharge flange 58, a weir 60 disposed
intermediate a pump feed section 53 of the separator 50 and a primary
section 55 of the separator, a mist eliminator 58, and a liquid/gas
interface sensor 68 such as, for example, a guided wave radar interface
sensor that generates a signal 84 to a controller 82. The water discharge
flange 58 is connected to a water discharge pipe 63 and that an oil/water
interface sensor (not shown) may be disposed to access the liquid section
55 of the separator. The oil/water interface sensor (not shown) generates
a signal (not shown) to the controller 82 which causes the control valve
to open in response to an elevated oil/water interface position, thereby
moving water from the liquid section 55 of the separator 50 through the
water discharge pipe 63 to maintain the location of the oil/water
interface within a predetermined operating range.

[0065] A plurality of pressure sensors may also be disposed at various
positions to facilitate feedback and control capability. For example, a
pressure sensor 62 may be disposed to sense the pressure of the liquid
stream removed from the monitored section 53 of the separator 50 through
the liquid discharge pipe 66, and to generate a signal 86 corresponding
to the pressure in the separator 50 to the controller 82. Alternately, a
pressure sensor 61 may be disposed to sense the pressure of the gas
stream removed from the monitored section 53 of the separator 50 through
the gas discharge pipe 64, and to generate a signal 70 to the controller
82. It will be understood that either of these pressure sensors will
provide a signal that generally corresponds to the pressure in the
separator 50. In addition, a pressure sensor 65 may be disposed on the
portion of the liquid discharge pipe 66 downstream of the liquid pump 71
to generate a signal 74 to the controller 82. In addition, a pressure
sensor 67 may be disposed on the liquid gathering pipe 96A to generate a
signal 77 to the controller 82.

[0066] Also supported on the skid 51 along with the separator 50 is a
liquid pump 71 fluidically connected to the liquid discharge pipe 66 at a
pump inlet 72 and fluidically connected to a pump outlet 79. The liquid
pump 71 receives oil or an oil and water mixture from the liquid
discharge pipe 66 and boosts the pressure of the liquid discharged from
the separator 50 through the pump 71 and into the pump discharge pipe 79
by, for example, 50 psig to 150 psig to suppress the formation of bubbles
in the liquid and to thereby facilitate accurate metering of the liquid
at a flow meter 78 disposed downstream of the liquid pump 71. Also
supported on the skid 50 at a position downstream of the flow meter 78 is
an automated liquid sampler 76. Optionally, an actuated control valve 80
may be provided on the skid 50 at a position downstream of the flow meter
78 and downstream of the automated liquid sampler 76. Optionally, the
actuated control valve 80 can be located off the skid 50, for example,
downstream of the liquid gathering pipe flange 96 but upstream of the
pressure sensor 67.

[0067] The pump 71 is operated by an electrically-powered pump motor 73.
In one embodiment of the present invention, the pump motor 73 receives a
signal 85 from a controller 82 that controls the speed of the pump motor
73 and the throughput of the pump 71. Alternately, the pump motor 73
receives a signal 85 in the form of a conditioned current from a current
conditioning device, such as a variable frequency drive (not shown),
that, in turn, receives the signal 85 from the controller 82. The signal
85 to the pump motor 73, whether or not conditioned by a current
conditioning device, corresponds to a signal 84 received by the
controller 82 from the liquid/gas interface sensor 68. For example, where
the liquid/gas interface sensor 68 detects an elevated liquid/gas
interface (not shown) at or near the top portion of an operating range
(not shown), the liquid/gas interface sensor 68 generates a signal 84
corresponding to a the elevated position of the liquid/gas interface and,
in response to receiving the signal 84, the controller 82 generates a
corresponding signal 85 to the pump motor 73 or, alternately, to a
current conditioning device, such as a variable frequency drive, to
increase the flow rate at which liquid is removed from the monitored
section 53 of the separator 50 through the liquid discharge pipe 66 and
the liquid pump 71. Conversely, where the liquid/gas interface sensor 68
senses that the liquid/gas interface is at or near the bottom of the
operating range (not shown), the liquid/gas interface sensor 68 generates
a signal 84 corresponding to a low position of the liquid/gas interface
and, in response to receiving the signal 84, the controller 82 generates
a corresponding signal 85 to the pump motor 73 or, alternately, to a
current conditioning device, such as a variable frequency drive, to
decrease the speed and the volumetric rate at which liquid is removed
from the monitored section 53 of the separator 50 through the liquid
discharge pipe 66 and the liquid pump 71. For embodiments having a
current conditioning device, such as a variable frequency drive, to
supply a conditioned current to the pump motor 73, the controller 82
would be programmed to generate a signal 85 corresponding to the flow
rate at which the liquid pump 71 should operate to restore the liquid/gas
interface to the desired position within the separator 50.

[0068] The controller 82 may, in one embodiment, be a programmable logic
controller (PLC) for receiving one or more signals from and for sending
one or more signals to a plurality of devices such as, for example, but
not by way of limitation, receiving a signal 84 from the liquid/gas
interface sensor 68, sending a signal 85 to the pump motor 73, receiving
a signal (not shown) from the meter 78, sending a signal (not shown) to
the automated liquid sampler 76, receiving a signal (not shown) from the
oil/water interface sensor (not shown), sending a signal (not shown) to a
gas discharge back-pressure valve (not shown), sending a signal 81 to a
back pressure control valve 80, receiving signals 77, 86, 74, and 70 from
pressure sensors 67, 62, 65 and 61, respectively, and for sending signals
to and/or receiving signals from other devices and/or equipment that may
be on the skid 51 or, alternately, that may be off the skid 51 such as,
for example, on a docking station 100 (not shown in FIG. 3--see FIG. 4)
that couples to pieces of equipment on the skid 51 or devices and/or
equipment that may be distanced from hydrocarbon processing equipment for
compliance with codes and standards.

[0069] The inlet flange 52, the gas discharge flange 54, the liquid
discharge flange 56 and the water discharge flange 58 are, in the
embodiment of the skid-mounted separator 50 of FIG. 3, disposed at a
first end 51A of the skid 51 to facilitate the convenient connection of
these flanges to corresponding flanges that may, in one embodiment, be
provided on a docking station. A docking station (not shown in FIG. 3)
facilitates the coupling of the second end of a flow line 92 to the
separator inlet flange 52, the gas gathering pipe 94 to the gas discharge
pipe 64, the liquid gathering pipe 96A to the liquid discharge pipe 66
(through other devices installed therein) and the water gathering pipe 98
to the water discharge flange 58, respectively. It not necessary that all
flanges on the skid be co-extensive or aligned with each other for with
the first end 51A of the skid 51 and, in other embodiments, one or more
of the inlet flange 52, gas discharge flange 54, oil discharge flange 56
and the water discharge flange 58 may be offset (to be non-co-extensive)
or positioned for engaging a corresponding pipe and flange along the
front of the skid 51 that is disposed toward the viewer of FIG. 3
(instead of the end of the skid as illustrated in FIG. 3). A skid 50 can
be, in some embodiments, slid or rolled into position for making
connections along one, two or even three sides of the skid 51 but
positioning of the skid 51 on the skid support 90 to be coupled to the
docking station is made more convenient by disposing the flanges for
making connections along only one end, one side, or at one end and one
adjacent side of the skid 51. It will be understood that although these
flanges illustrated in FIG. 3 are facing outwardly away from the skid 50,
other embodiments may provide flanges facing upwardly, downwardly or even
inwardly without impairment of the function of the flanges. It will be
further understood that flanges are shown in FIG. 3 merely for
convenience, and that other connections, such as screwed connections, are
equally useful.

[0070]FIG. 4 is an elevation view of an embodiment of a docking station
that can be used to connect to the skid-mounted separator 50 of FIG. 3
and related equipment of FIG. 3 to implement an embodiment of the method
and system of the present invention. The embodiment of the docking
station of FIG. 4 comprises the skid support 90, a flow line 92A
terminating at a flow line flange 92, a liquid gathering pipe 96A
terminating at a liquid gathering pipe flange 96, a gas gathering pipe
94A terminating at a gas gathering pipe flange 94, and a water gathering
pipe 98 terminating at a water gathering pipe flange 98A. It should be
noted that the section view line on FIG. 3 is staggered, near the bottom,
to include a small part of the end portion 51A of the skid 51 and the
skid support 90. It should also be noted that the configurations of the
pipes and flanges on FIG. 4 is but one possible arrangement of
positioning the flanges 92, 94, 96 and 98 on the docking station to
engage and coupled to the corresponding flanges 52, 54, 56 and 58
supported on the skid 51 or, alternately, on the turndown skid to be
discussed in more detail below.

[0071]FIG. 5A is a perspective view elevation view of one embodiment of a
liquid pump 71 and pump motor 73 of a kind and type that could be
supported, for example, on the skid 51 of FIG. 3 and that could be used
to implement various embodiments of the method and system of the present
invention. The portions of the liquid discharge pipe 66 (shown in FIG. 3)
are removed from both the pump suction flange 71A and the pump discharge
flange 71B in FIG. 5A to better reveal the liquid pump 71, which may be,
for example, a gear pump. A pump motor 73 is illustrated as being coupled
to the liquid pump 71 through a rotatable shaft 75 to provide power to
the internal pump components (not shown) to move and pressurize the
liquid (not shown) entering the pump suction flange 71A from the pump
feed section 53 (see FIG. 3) of the separator 50 (see FIG. 3).

[0072] Using a gear pump for the liquid pump 71 may provide the advantages
of an available high pressure differential across the liquid pump 71 and
a broad turndown range. These features may provide great flexibility to
the system and method. The example of the liquid pump 71 illustrated in
FIG. 5A is but one of many pump and motor combinations that may be used
to implement the method and system of the present invention. For example,
but not by way of limitation, FIG. 5B illustrates an alternate embodiment
of the liquid pump 71 and pump motor 73 wherein the liquid pump 71 is a
centrifugal pump.

[0073] FIGS. 5A and 5B illustrate embodiments of pump and motor
combinations that could be used in embodiments of the method and system
of the present invention. In an alternative embodiment, the liquid pump
and pump motor may comprise a pump assembly having a motor, a pump,
non-magnetic case or a non-magnetic case portion of a non-magnetic
material such as, for example, stainless steel, high-strength plastic or
carbon composite, to facilitate the magnetic transfer of torque from an
output shaft of a the motor, such as an electrically-powered motor, to
the internal rotating element of the pump using a magnetic coupling. A
magnetic coupling uses a plurality of leader magnets coupled to the pump
motor output shaft for rotation about an axis of the shaft and in close
proximity to a plurality of corresponding follower magnets coupled to the
pump input shaft, impeller shaft, etc. to magnetically transfer torque
from the shaft of the output pump motor to the input shaft of the pump.
The leader magnets on the pump motor output shaft and the follower
magnets on the liquid pump input shaft may be strategically oriented to
present compatible polarity and to promote optimal attraction and optimal
torque transfer from the pump motor to the pump. The use of a magnetic
coupling in this manner eliminates the need for the use of seals to
contain and isolate the high-pressure liquid stream within the pump.

[0074] The gear pump of FIG. 5A provides operational advantages over other
pumps such as, for example, the centrifugal pump of FIG. 5B. For example,
the purpose of the liquid pump is to enable and provide control of the
rate at which liquid is removed from the monitored section of the
separator, and the throughput of a gear pump is primarily determined by
the speed and is generally immune to the discharge pressure. Some
embodiments of the method and system of the present invention include
providing a back pressure control valve downstream of the liquid pump so
that the liquid meter is intermediate the liquid pump and the back
pressure control valve. In these embodiments, the back pressure control
valve may be used to control the pressure of the liquid stream at the
liquid meter and at any automated liquid sampler or densitometer that may
be provided intermediate the liquid pump and the back pressure control
valve to ensure that the pressure at which metering and sampling occurs
is above the bubble point of the liquid stream removed from the
separator. This combination of a positive displacement pump, capable of
being operated at varying speeds to provide control of the rate of
removal of liquid from the monitored section of the separator, and a back
pressure control valve positioned downstream of the liquid meter, enables
favorable control of the liquid/gas interface within the monitored
section of the separator and, at the same time, favorable maintenance of
the pressure at the liquid meter above the bubble point.

[0075] The motor used to operate the liquid pump may be
electrically-powered and, more specifically, may be either direct current
(DC) or alternating current (AC). In an embodiment of the method and
system of the present invention in which the motor is a DC motor, the DC
motor may be a servo-motor and the DC current may be provided to the
motor by a bank of batteries that are periodically rechargeable using,
for example, solar panels, where climate is favorable, or using a diesel,
gasoline or produced hydrocarbon gas-powered generator. The controller
may be used to monitor the status of the batteries and to manage the
recharging of the batteries.

[0076] In an embodiment of the method and system of the present invention
in which the motor is an AC motor, the current may be provided by a
lateral from an electric power distribution grid. It will be further
understood that such DC or AC sources may further be used to power
chemical injection pump motors, to operate operating feedback and control
systems, actuated valves and communications systems for communicating
status and alerts to remotely monitored systems. For AC pump motor
embodiments, the frequency of the alternating current may be directed by
the controller in response to the signal from the liquid/gas interface
sensor, and a variable frequency drive (VFD) may be provided at the well
location, but distanced from the separator and other hydrocarbon
processing equipment according to codes and rules, to receive and
condition AC power from a power distribution grid in accordance with the
requirements as instructed by the controller.

[0077]FIG. 6 is a schematic illustrating the input and/or output
connections of a controller 82 electronically coupled to the pump motor
73, an automated liquid sampler 76, a gas/liquid interface sensor 68, a
flow meter 78, a liquid back pressure control valve 80, an emergency
shut-down (ESD) system 88, a first pressure sensor 62, a second pressure
sensor 65, a third pressure sensor 67, and a chemical injection pump
motor 91. It should be understood that some of these and other devices
may be used to generate input signals to the controller 82 such as, for
example, but not by way of limitation, a pressure sensors 62, 65 and 67
to generate signals 86, 74 and 77 corresponding to the sensed pressures
in the liquid discharge pipe 66 (shown in FIG. 3) just removed from the
separator 50 (which is approximately the separator pressure), the portion
of the liquid discharge pipe 66 (shown in FIG. 3) downstream of the pump
71 (shown in FIG. 3) but upstream of the back pressure control valve 80
(shown in FIG. 3), and the liquid gathering pipe 96A (shown in FIG. 3)
downstream of the back pressure control valve 80 (shown in FIG. 3),
respectively. Additionally, an oil/water interface sensor (not shown in
FIG. 3) may generate a signal corresponding to the position of the
oil/water interface in a water section of the separator, a water dump
valve (not shown) may receive a signal generated by the controller 82 to
open or close to adjust the position of the oil/water interface in the
separator. It will be understood that the ESD system 88 may, in one
embodiment, be in pneumatic or electronic communication with, for
example, an ESD valve (not shown) at a wellhead (which may be referred to
as the first end of the flow line (see element 92A on FIG. 3, which is
the second end of the flow line) that can be actuated to close in the
event of, for example, an excessively high oil/water interface in the
separator, an excessively high or low liquid/gas interface in the
separator, an excessively high or low separator pressure, a failure or
impairment of the liquid pump, or other conditions that may warrant a
shut-in of the well and/or the equipment on the skid.

[0078] The controller 82 may, in one embodiment, be a single controller
or, in other embodiments, two or more controllers programmed to cooperate
with one or more others to accomplish the objectives for which they are
programmed. It will be understood that the controller 82 is illustrated
to be in more than one location on FIG. 3 merely for purposes of
convenience of illustration, and that an actual controller may be a
single device located in a single location and connected to numerous
devices. It should be further understood that a controller may be
connected wirelessly, by electrically conductive wires, by optically
conductive fibers, pneumatic conduits, and by other means known in the
art for transmitting signals from one device to another.

[0079]FIG. 7 is a side elevation view of an embodiment of a liquid
stabilizer tower 201 that may be used at a central conditioning facility
fed by the liquid stream discharged from the separator 50 through the
liquid discharge pipe 66 and to the liquid gathering pipe 96A (see FIG.
3), and by commingled or isolated liquid streams received into the
central conditioning facility from other separators at other well
locations, all aggregated together to form a liquid stream 194A entering
the stabilizer tower 201 in FIG. 7. In one embodiment, the stabilizer
tower 201 comprises a plurality of trays 201A, spaced apart one from the
others and arranged in a generally vertical stack to facilitate the
establishment of a tray-by-tray equilibrium in which lighter hydrocarbon
components in the liquid such as, for example, propane and butane,
evaporate and rise from a given tray and move through valves or openings
in the adjacent tray above, while heavier hydrocarbon components such as,
for example, pentane and hexane, remain in liquid form and descend from a
given tray through down-comers located in or adjacent to the tray and to
the tray therebelow.

[0080] A reboiler 207 may be disposed to receive the stream 224 of heavier
(liquid) hydrocarbon components of the liquid stream discharged from the
bottom section 222 of the stabilizer tower 201. The reboiler 207 may
comprise a shell and tube heat exchanger in which heat from a heat source
209, such as steam or heat medium oil, is imparted to the stream 224 from
the bottom section 222 to evaporate some of the lighter hydrocarbon
components of the liquid stream to maintain tower dynamics. The reboiler
207 may be equipped with a rundown line 229 through which liquid having
an adjusted vapor pressure may feed to a receiving and/or storage vessel,
such as a stock tank or pipeline pump suction tank 203. A condenser 208
may be disposed to receive the stream 223 of lighter (gaseous) components
of the liquid (primarily hydrocarbons) discharged from the top section
221 of the stabilizer tower 201. The condenser 208 may also comprise a
shell and tube heat exchanger in which heat from the gas stream 223
discharged from the top section 221 of the stabilizer tower 201 can be
removed to or sunk into a stream of a cooler medium 206 such as, for
example, ambient or chilled water. In other embodiments, an aerial cooler
may be used to remove heat from the gas stream 223 and/or a waste heat
source from another system, such as, for example, combustion products,
may be used to heat the liquid stream 224. A reflux drum 202 may be used
to receive the cooled hydrocarbon stream from the condenser 206 to
separate the stream into a gas stream 225 (primarily ethane and propane),
a waste water stream 228 and a condensed liquid stream 227 that is
returned to the stabilizer tower 201 as reflux through valve 210 or,
alternately, it can be routed through valve 211 to a receiver 204 or
other storage vessel.

[0081] Where the commingled streams of liquid to be fed into the
stabilizer tower of FIG. 7 comprises a mixture of liquid hydrocarbons
(oil or condensate) and water, it is advantageous to separate the liquid
hydrocarbon component from the water prior to feeding the liquid
hydrocarbon component into the stabilizer tower. Where the separator at
the well location (for example, the separator 50 in FIG. 3) is a
two-phase separator, the removal of water from the commingled liquid
stream prior to introducing of the commingled liquid stream into the
stabilizer tower may be required for favorable stabilizer performance.
Where the separator at the well location is a three-phase separator,
which separates water from a liquid hydrocarbon stream, the separation
step prior to introducing the commingled liquid stream into the
stabilizer at the central conditioning facility may be unnecessary.

[0082] A stabilizer tower 201 can provide for removal of unwanted lighter
hydrocarbon components from the commingled liquid stream to a gas phase
so that the lighter hydrocarbon components may be advantageously removed
from the stabilizer tower 201 top section 221 while retaining the heavier
hydrocarbon components in the liquid phase that is removed from the
stabilizer tower 201 at the bottom section 222. In this manner, an
aggregate liquid stream 194A comprising the liquid streams removed from
separators at a plurality of contributing wells (96A and others) may be
economically conditioned at the central conditioning facility illustrated
in FIG. 7 to provide a favorable vapor pressure of the liquid stream to
avoid deductions from the sale price by a purchaser. The removed propane
or other lighter hydrocarbon components may be transported to market from
the central conditioning facility via mobile transport, such as a truck.

[0083] It should be understood that embodiments of the method and system
of the present invention may be used without a central conditioning
facility, and that the conditioning of the commingled liquid stream from
multiple wells does not necessarily require a stabilizer with a reboiler
and a reflux system. Instead, the commingled liquid stream may be
conditioned by receiving the commingled stream into a slugcatcher, bullet
or separator, but these options do not provide the same capacity to
selectively remove the lighter hydrocarbons and to thereby condition the
liquid for favorable pricing.

[0084]FIG. 8 is a side elevation view of an embodiment of a second,
alternate skid 51 supporting a liquid pump 71, a pump motor 73, a flow
meter 78, an automated liquid sampler 76, a chemical injection pump 93
and a chemical injection pump motor 91. The second, alternate skid 51
illustrated in FIG. 8 may be connected to a separator (not shown)
supported off the skid. A connecting pipe may be fabricated to facilitate
providing a liquid stream from a separator liquid discharge flange (not
shown in FIG. 8) on, for example, a two-phase or three-phase separator
located off-skid, to the pump suction flange 71A or other type of (e.g.,
screwed) connection to the pump inlet. The second skid 51 and the
equipment thereon in FIG. 8 may be used to implement the method and
system of the present invention using an existing separator at a well
location or, optionally, using a separator on an adjacent skid. This
alternate method and system permits the use of a smaller skid 51 as
compared to the skid that would be required to support these same pieces
of equipment along with a separator, and the embodiment illustrated in
FIG. 8 enables cost reduction through the continued use of an existing
separator and related gas discharge and water discharge pipes, valves,
instrumentation and hardware.

[0085] The chemical injection system comprising the chemical injection
pump 93, the chemical injection pump motor 91 and a container of chemical
to be injected (not shown), for example, but not by way of limitation, a
barrel or drum of scale inhibitor, corrosion inhibitor, paraffin
inhibitor, emulsion breaker or friction reducing agent, can be disposed
on the skid 51 or off-skid and connected to an inlet (not shown) on the
chemical injection pump 93 and pressurized chemical is injected by way of
chemical pump discharge conduit 95 at, for example, the inlet flange 71A
of the liquid pump 71. The rate at which the chemical pump 93 operates
and the corresponding concentration of the chemical in the liquid flow
stream through the liquid pump 71, the automated oil sampler 76, the flow
meter 78, the back pressure control valve 80 and the liquid gathering
pipe 96A is controlled using the controller 82. The controller 82
generates a signal 97 to the chemical injection pump 91 corresponding to
the signal 85 (not shown--see FIG. 6 and FIG. 3) to the liquid pump motor
73. It will be understood that the controller 82 may generate a signal to
the chemical injection pump motor 91 corresponding to the signal 85
generated by the controller 82 to the liquid pump motor 73 because the
two should operate in harmony to ensure that the concentration of the
chemical in the liquid flow stream removed from the separator is as
prescribed by the chemical manufacturer or otherwise in a concentration
that is effective for the intended purpose. It will be further understood
that this method of controlling the rate at which chemical agents are
injected into the liquid flow stream being removed from the separator
conserves expensive chemicals by preventing injection rates above an
effective concentration. Alternatively, the chemical may be set to inject
proportional to the mass or volumetric flow of the liquid.

[0086]FIG. 9 is an elevation view of an embodiment of a docking station
that may be used to couple to the equipment supported on the second,
alternate skid of FIG. 8 that may be used to implement an alternate
embodiment the method and system of the present invention. The docking
station of FIG. 9 comprises a skid support 90 positioned to support the
skid 51 of FIG. 8 in a position to facilitate the connection of the
liquid gathering pipe 96A and the related flange 96 of FIG. 8 to the
liquid pipe discharge flange 99 on the skid 51 on FIG. 8. The optional
actuated control valve 80 may be used to control the pressure of liquid
stream discharged from the skid 51 to the liquid gathering pipe 96A. The
actuated control valve 80 may be controllable by way of a signal 81 from
the controller 82. The actuated control valve 80 may be, in other
embodiments, located off-skid. The speed and throughput of the pump 71
may also be controllable by the controller 82 sending a signal 85 to the
pump motor 73.

[0087]FIG. 10 is a side elevation view of an embodiment of a second,
turndown skid 151 supporting a second, smaller separator 150 and related
equipment supported on a skid support 90 to facilitate docking of the
second skid 151 and the separator 150 supported thereon with a docking
station, such as that illustrated in FIG. 4. The embodiment of the second
skid 151 illustrated in FIG. 10 comprises a first end 151A at which inlet
flange 152, gas discharge pipe flange 195 and liquid discharge pipe
flange 197 are conveniently positioned to be coupled to a flange 92 on
the second end of a flow line 92A, a flange 94 on the gas gathering pipe
94A and a flange 96 on the liquid gathering pipe 96A, respectively. The
smaller separator 150 illustrated in FIG. 10 comprises a mist eliminator
158, a weir 160, a gas discharge flange 154, a liquid discharge flange
156 and a pair of separator supports 169 spaced one from the other to
support the separator 150 at a spaced distance from the second skid 151.
The second skid 151 further supports a liquid pump 171 coupled to be
operated by a pump motor 173 adjacent thereto, an automated liquid
sampler 176, a liquid flow meter 178 positioned downstream of the liquid
pump 171, and an optional control valve 180. A liquid/gas interface
sensor 168 such as, for example, a guided wave radar sensor, generates a
signal 84 corresponding to the detected liquid/gas interface (not shown)
within the second separator 150 to a controller 82 that, in turn,
generates a signal 85 to the pump motor 173 to speed up or slow down the
liquid pump 171 to maintain the volume of liquid in the monitored section
153 of the second separator 150 within a desired operating range.

[0088] The second separator 150 on the second skid 151 illustrated in FIG.
10 may be substantially smaller than the first separator 50 on the first
skid 51 in FIG. 3, and the second separator 150 may have a substantially
smaller throughput capacity than the first separator 50. The related
piping and equipment on the second skid 151 may also be smaller in size
and capacity as compared to the comparable structures illustrated in FIG.
3. For efficiency and interchangeability, the size of the various flanges
and connections used on the liquid pump 171, the pump motor 173, the
liquid flow meter 178, and the automated liquid sampler 176 may be
maintained from the first skid 51 to the second skid 151, and that
concentric and/or eccentric reducers and similar pipe fittings (not shown
in FIG. 10) may be employed to accommodate smaller piping for lower flow
rates such as, for example, the gas discharge pipe 164 in FIG. 10.
Additionally, the turndown skid may have differently sized pumps, piping
and flow meter. To promote efficiency and to expedite skid replacement
and turndown of the production facility, it is advantageous if connecting
flanges 197 (to liquid gathering line), 195 (to gas gathering line) and
152 (separator inlet line), and perhaps a connecting flange on the water
pipe, be of the same size and pressure rating for both the turndown skid
(e.g., of FIG. 10) and the first skid (e.g., of FIG. 3).

[0089]FIG. 11 is a high-level flow chart illustrating an embodiment of a
method for metering liquids produced from a well using the methods and
systems of the present invention. Steps 200 through 265 illustrate one
embodiment of implementing the method of the present invention to produce
a well. In step 200, a first separator having an inlet flange, a gas
discharge flange, liquids discharge flange, a liquid/gas interface sensor
and a liquids flow meter is provided. In step 205, a docking station
comprising a flow line, a gas gathering pipe, and a liquid gathering pipe
to facilitate connections to the inlet flange, the gas discharge flange
and the liquid discharge flange is provided. In step 210, the liquids
flow meter is connected to the oil discharge flange of the separator and,
in step 215, the automated liquid sampler is connected to the oil
discharge flange of the separator. In step 220, a liquid pump is
connected intermediate the liquid discharge flange of the separator and
both the automated liquid sampler and the liquid flow meter to vary the
flow rate of liquid from the separator and through the automated liquid
sampler and the liquid flow meter to facilitate control of the liquid/gas
interface in the monitored section of the separator while providing
additional pressure boost to ensure that the liquid being metered and
sampled in the liquid flow meter and the automated liquid sampler is
above the bubble point of the liquid. In step 230, the separator inlet
flange is connected to the flow line, in step 235, the separator gas
discharge pipe is connected to the gas gathering pipe and, in step 240,
the separator liquid discharge flange is connected to the liquid
gathering pipe. In step 245, full well stream production from a well is
received through the flow line and the inlet flange and into the
separator. In step 250, an elevated liquid/gas interface is detected
using the liquid/gas interface sensor on the separator. In step 255, the
liquid/gas interface sensor is used to generate a signal to a controller.
In step 260, the controller is used to activate the pump motor to operate
at an increased speed and, in step 265, the increased speed of the pump
motor results in an increase in the rate of removal of liquid from the
section of the separator that is monitored by the liquid/gas interface
sensor. In a subsequent step not illustrated in FIG. 11, the liquid/gas
interface sensor senses a corrected position of the liquid/gas interface
in the monitored section of the separator and the liquid/gas interface
sensor generates a signal to the pump motor to slow the speed of the pump
to thereby decrease the rate of removal of liquid from the monitored
section of the separator. It will be understood that, by continuing to
use the liquid/gas interface sensor to control the speed of the pump
motor and the throughput of the pump, the liquid/gas interface in the
monitored section of the separator can be maintained within a desired
operating range while maintaining the pressure of the liquid stream
flowing through the liquid flow meter and the automated liquid sampler
above the bubble point.

[0090]FIG. 12 is a flow chart illustrating the steps of an embodiment of
a method for determining the hydrocarbon production for a well by
metering at the well surface location in accordance with the present
invention. In step 300, a first separator having an inlet flange, a gas
discharge flange, a liquid discharge flange, a liquid/gas interface
sensor, a pump, a pump motor and an automated liquid sampler is provided.
In step 305, a well flow line, a gas gathering pipe, and a liquid
gathering pipe, each having a flange to facilitate connection to the
inlet flange, the gas discharge flange and the liquid discharge flange
are provided. In step 310, a liquid flow meter is coupled to the
discharge flange of the separator to meter the flow rate of the liquid
discharged from the separator through the liquid discharge flange. In
step 315, an automated liquid sampler is coupled to the discharge flange
of the separator to facilitate the periodic removal and storage of
samples of the liquid stream discharged from the separator through the
liquid discharge flange. In step 320, a pump is coupled intermediate the
liquid discharge flange of the separator and both of the liquid flow
meter and the automated liquid sampler to facilitate control of the
liquid/gas interface in the monitored section of the separator while
providing additional pressure boost to ensure that the liquid being
metered and sampled in the liquid flow meter and the automated liquid
sampler is above the bubble point of the liquid. In step 330, the
separator inlet flange is connected to the flow line from the well. In
step 335, the gas discharge flange is coupled to the gas gathering pipe
and, in step 340, the liquid discharge flange is coupled to the liquid
gathering pipe (through the pump, the liquid flow meter and the automated
liquid sampler). In step 345, full well stream is received from a well
through the flow line and the inlet flange and into the separator. In
step 350, an elevated liquid/gas interface is detected in the monitored
section of the separator using the liquid/gas interface sensor. In step
355, the liquid/gas interface sensor is used to generate a signal to a
controller and, in step 360, the controller is used to activate the pump
motor to operate at an increased speed to, in step 365, increase the rate
of removal of liquid from the monitored section of the separator. In step
370, the flow rate of liquid removed from the monitored section of the
separator through the liquid discharge flange is measured using the flow
meter and, in step 375, the measurements of the liquid flow rate through
the meter over a period of time are recorded. In step 380, a plurality of
liquid samples are obtained and stored using the automated liquid sampler
and, in step 385, an average chemical composition of the liquid samples
obtained using the automated liquid sampler is obtained by, for example,
using chromatographic analyses performed in a laboratory to determine a
distribution of hydrocarbon molecules in a composite of the accumulated
and stored samples. Finally, in step 390, the recorded liquid flow rate
data and the chemical composition data obtained in step 385 are together
used to determine the amount of liquid and, more specifically, the amount
of the various hydrocarbons produced by the well during the period of
time. In a subsequent step, not illustrated in FIG. 12, the royalties due
to a mineral interest owner in the well are calculated using the recorded
liquid flow rate data and the chemical composition data obtained in step
385 are determined and paid by the well operator.

[0091] The term "liquid," as that term is used herein, may refer to oil,
condensate, an oil and water mixture, a condensate and water mixture,
and/or to other mixtures comprising at least one hydrocarbon liquid. The
terms "comprising," "including," and "having," as used in the claims and
specification herein, shall be considered as indicating an open group
that may include other elements not specified. The terms "a," "an," and
the singular forms of words shall be taken to include the plural form of
the same words, such that the terms mean that one or more of something is
provided. The term "one" or "single" may be used to indicate that one and
only one of something is intended. Similarly, other specific integer
values, such as "two," may be used when a specific number of things is
intended. The terms "preferably," "preferred," "prefer," "optionally,"
"may," and similar terms are used to indicate that an item, condition or
step being referred to is an optional (not required) feature of the
invention.

[0092] While the invention has been described with respect to a limited
number of embodiments, those skilled in the art, having benefit of this
disclosure, will appreciate that other embodiments can be devised which
do not depart from the scope of the invention as disclosed herein.
Accordingly, the scope of the invention should be limited only by the
attached claims.